ULNRC-05362, Response to NRC Request for Additional Information Regarding Letter 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power.

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Response to NRC Request for Additional Information Regarding Letter 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power.
ML070380274
Person / Time
Site: Callaway Ameren icon.png
Issue date: 01/31/2007
From: Fitzgerald D
AmerenUE
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
GL-06-002, ULNRC-05362
Download: ML070380274 (10)
v • d • e


Text

AnmerenUE Callaway Plant PO Box 620 Fulton, MO 65251 January 31, 2007 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop P1-137 Washington, DC 20555-0001 Ladie A meremn UE s and Gentlemen:

ULNRC-05362 DOCKET NUMBER 50-483 CALLAWAY PLANT UNIT 1 UNION ELECTRIC CO.RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING GENERIC LETTER 2006-02,"GRID RELIABILITY AND THE IMPACT ON PLANT RISK AND THE OPERABILITY OF OFFSITE POWER"

References:

1.USNRC Generic Letter 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," dated February 1, 2006 2. AmerenUE letter ULNRC-05270, "60-Day Response to NRC Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power,"' dated March 31, 2006 3. AmerenUE letter ULNRC-05313, "Follow-up Response to NRC Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power,"' dated August 1, 2006 4. USNRC Letter, "Request for Additional Information Regarding Resolution of Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power' (TAC Nos. MD0947 through MD 1050)," dated December 5, 2006 On February 1, 2006, the NRC issued Generic Letter (GL) 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," (Reference 1). The GL sought to obtain information from licensees to determine if compliance is being maintained with NRC regulatory requirements governing electric power sources and associated personnel training.

AmerenUE (Union Electric) provided its response for Callaway Plant by letter dated March 31, 2006 (Reference 2), as modified by a follow-up letter dated August 1, 2006 (Reference 3).A23 a subsidiary of Ameren Corporation ULNRC-05362 January 31, 2007 Page 2 From its review of all the licensee responses to GL 2006-02, the NRC determined that additional information is needed to resolve some of the issues discussed in the GL.By letter dated December 5, 2006 (Reference

4) the NRC issued a request for additional information (RAI) to licensees.

The specific questions asked per the RAI were listed in Enclosure 2 of the letter. Since not all of the RAI questions pertain to each plant, Enclosure 3 of the letter provided a listing that identifies which questions apply to which facility.

For Callaway Plant, RAI questions 1, 4, and 5 were identified to be applicable.

In response to the NRC's RAI, AmerenUE hereby provides the additional information requested for Callaway Plant, i.e., responses to questions 1, 4, and 5 of the RAI. The responses are provided in the attachment to this letter.It may be noted that no regulatory commitments are made per this letter or its attachment.

For any questions regarding this letter or its attachment, please contact David Shafer at either 314-554-3104 or 573-676-4722.

I declare under penalty of perjury that the foregoing and attached are true and correct.Sincerely, Executed on January 31, 2007 David T. Fitzgerald Manager-Regulatory Affairs TBE/jdg Attachment ULNRC-05362 January 31, 2007 Page 3 cc: Mr. Bruce S. Mallett Regional Administrator U.S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-4005 Senior Resident Inspector Callaway Resident Office U.S. Nuclear Regulatory Commission 8201 NRC Road Steedman, MO 65077 Mr. Jack N. Donohew (2 copies)Licensing Project Manager, Callaway Plant Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop O-7D1 Washington, DC 20555-2738 Missouri Public Service Commission Governor Office Building 200 Madison Street PO Box 360 Jefferson City, MO 65102-0360 Mr. Ron Reynolds Director Missouri State Emergency Management Agency P.O. Box 116 Jefferson City, MO 65102 ULNRC-05362 January 31, 2007 Page 4 bcc: C. D. Naslund A. C. Heflin D. T. Fitzgerald L. E. Thibault T. E. Herrmann D. W. Neterer G. A. Hughes D. E. Shafer T. B. Elwood (470)S. L. Gallagher (100)L. M. Belsky (NSRB)D. R. Waller D. S. Turley M. L. Wedel (630)J. V. Hackman (630)A160.0761 Certrec Corporation 4200 South Hulen, Suite 630 Fort Worth, TX 76109 (Certrec receives ALL attachments as long as they are non-safeguards and publicly disclosed).

Send the following without attachments:

Ms. Diane M. Hooper Supervisor, Licensing WCNOC P.O. Box 411 Burlington, KS 66839 Mr. Scott Bauer Regulatory Affairs Palo Verde NGS P.O. Box 52034, Mail Station 7636 Phoenix, AZ 85072-2034 Mr. Scott Head Supervisor, Licensing South Texas Project NOC Mail Code N5014 P.O. Box 289 Wadsworth, TX 77483 Mr. Dennis Buschbaum TXU Power Comanche Peak SES P.O. Box 1002 Glen Rose, TX 76043 Mr. Stan Ketelsen Manager, Regulatory Services Pacific Gas & Electric Mail Stop 104/5/536 P.O. Box 56 Avila Beach, CA 93424 Mr. John O'Neill Pillsbury Winthrop Shaw Pittman LLP 2300 N. Street N.W.Washington, DC 20037 Attachment to ULNRC-05362 AmerenUE Response to Request for Additional Information (RAI)Regarding Information and Responses Provided for Callaway Plant in Response to Generic Letter 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power" By letter dated December 5, 2006 the NRC issued a request for additional information (RAI) to licensees regarding the information and answers provided by licensees in response to the topics and questions contained in GL 2006-02. The specific RAI requests/questions were listed in Enclosure 2 of the letter. Since not all of the RAI questions pertain to each plant, Enclosure 3 of the letter provided a listing identifying which questions apply to which facility.

For Callaway Plant, RAI questions 1, 4, and 5 were identified to be applicable.

In response to the RAI, AmerenUE provides the following responses to Questions 1, 4, and 5 for Callaway Plant. For each case, the RAI question is given, followed by AmerenUE's response.1. Switchyard Minimum Voltage: In response to question 1(g) [of the GL] you did not identify specific minimum switchyard voltage limits (kV) that you supplied to the local transmission entity. Please, provide the following information:

What is the specific minimum acceptable switchyard voltage included in your protocol agreement with your grid operator (GO) and what was the basis for this value? How is this value related to your Technical Specification degraded voltage relay setpoints?

AmerenUE Response: The specified minimum off-site switchyard voltage (post unit trip) is related to the voltage required to reset the Technical Specification degraded voltage relays plus an uncertainty which includes sensor accuracy and bistable setting tolerance.

The Technical Specification degraded voltage relays for Callaway Plant monitor the safety-related 4160-VAC buses and have a reset value of 3808 Volts. The relays have an associated time delay of 8 seconds with a safety injection (SI) signal present or 119 seconds without an ST signal present. This degraded voltage reset value corresponds to a switchyard voltage of 329.8 kV when computed using load flow analysis with safety injection loads present (

Reference:

Callaway calculation NB-05 and ZZ-62). Refer to the tables provided on pages 5 and 6 of this attachment for voltage operability values based on plant operating Mode and voltage regulating equipment line-up. The tables are taken from Callaway Plant Operations Surveillance Procedure OSP-NB-00001, "Class lE Electrical Source Verification." 1 of 6 Attachment to ULNRC-05362 As addressed by Callaway procedure OSP-NB-00001, when the main generator is on line, the actual switchyard voltage indicated on the main control board and the plant computer is not indicative of what switchyard voltage would be following a reactor trip. This is due to the voltage support provided by the main generator.

Therefore, when the generator is on line, a predicted contingency voltage that is determined from the Real Time Contingency Analysis (RTCA) program, along with the"Category 8 Alarm" that may be present, is used to determine OPERABILITY of the offsite AC sources. The Category 8 Callaway Switchyard Alarm is an Ameren Transmission Operator alarm actuated by the RTCA and is set approximately 3 kV above the OPERABILITY limit. Ameren Transmission Operations will respond to this alarm and take necessary actions to restore acceptable voltage in the transmission system.4. Identification of Applicable Single Contingencies:

In response to question 3(a) [of the GL] you did not identify the loss of other critical transmission elements that may cause the offsite power system (OSP) to degrade, other than the loss of the nuclear unit. If it is possible for specific critical transmission elements (such as other generators, critical transmission line, transformers, capacitor banks, voltage regulators, etc.) to degrade the OSP such that inadequate post-trip voltage could result, have these elements been included in your N-1 contingency analysis?

When these elements are included in your GO's contingency analysis model and failure of one of these transmission elements could result in actuation of your degraded voltage grid relay, is the offsite power declared inoperable?

If not, what is your basis for not declaring the offsite power inoperable?

AmerenUE Response: Both the Midwest Independent System Operator (MISO) and Ameren Transmission real time contingency analysis (RTCA) programs include N-1 contingencies for all major transmission lines, generation units and bulk transformers (e.g., 345 kV/13.8 kV) in their systems. At present, there are 460 N-1 contingencies factored into the Ameren Transmission RTCA program, which are run by the computer program on a six-minute interval.

The list is continually reviewed, and contingencies are added or modified as needed (such as when changes are made to the transmission system). These contingencies are run against the existing grid conditions and thereby used to predict the Cailaway switchyard post-trip voltage in the case of each contingency.

Although it is highly unlikely that a postulated loss of a facility other than the nuclear unit would degrade switchyard voltage to below the minimum required value with the Callaway main generator on-line, in the event the predicted voltage is below the "Category 8 Alarm" setpoint, Callaway Operations would be alerted to evaluate OPERABILITY of the off-site sources based on the requirements specified in 2 of 6 Attachment to ULNRC-05362 Callaway procedure OSP-NB-00001. (This procedure provides the minimum switchyard voltage that relates directly to the degraded voltage relay setpoints.)

In such cases, offsite source OPERABILITY may be conservatively assessed based on all contingencies factored into the RTCA; however, the offsite sources would not necessarily be declared inoperable for the postulated loss of a facility (other than the nuclear unit) without additional evaluations of overall grid conditions.

When the nuclear unit (Callaway Plant) is already off-line, Technical Specifications are not entered at Callaway Plant for grid conditions that might occur. Operability of the Callaway offsite power sources is monitored via the Category 8 Alarm and the predicted voltage value provided by the Ameren Transmission Operator.

If Callaway Plant is notified by the Ameren Transmission Operator that a Category 8 alarm is present, then operators will respond in accordance with OSP-NB-00001 and make a determination regarding offsite source operability based on the actual metered voltage. In this condition, postulated contingencies on the transmission grid are not used as a basis for operability determinations since:* Such events are only postulated and have not actually occurred.* The offsite power circuits remain capable of effecting a safe plant shutdown and mitigating the effects of an accident, and* The GDC-17 criterion discussed in the Generic Letter is still met, i.e., loss of power from the transmission network would not occur as a result of loss of power generated by Callaway Plant.It should be noted that compliance with GDC-17 was taken into account in the design and licensing of Callaway Plant. The requirements of the Technical Specifications with regard to the "qualified circuits between the offsite transmission network and the onsite Class IE AC electrical power distribution system" and the associated operability requirements specified therein are viewed to have a separate or different intent and scope relative to GDC-17. Nevertheless, procedures have been established based on application of the agreement with MISO and Ameren Transmission (as described in AmerenUE's March 31, 2006 response to GL 2006-02), and those procedures are used during plant operation to evaluate switchyard voltage levels for appropriate contingencies, including a Callaway Plant trip, and to thus conservatively assess operability of the offsite power system for determining whether entry into a Condition(s) and Required Action(s) of Callaway Technical Specification 3.8.1, "AC Sources-Operating," should be made.5. Seasonal Variation in Grid Stress (Reliability and Loss-of-offsite Power (LOOP)Probability):

Certain regions during certain times of the year (seasonal variations) experience higher grid stress as is indicated in Electric Power Research Institute (EPRI) Report 1011759, Table 4-7, Grid LOOP Adjustment Factor, and NRC NUREG/CR-6890.

Do you adjust the base LOOP frequency in your probabilistic risk assessment (PRA) and Maintenance Rule evaluations for various seasons? If 3 of 6 Attachment to ULNRC-05362 you do not consider seasonal variations in base LOOP frequency in your PRA and Maintenance Rule evaluations, explain why it is acceptable to do so.AmerenUE Response: As stated in AmerenUE's March 31, 2006 response to Question 5(c) of GL 2006-02, there are no apparent seasonal variations that affect LOOP frequency.

Consequently, Callaway does not adjust the base LOOP frequency in the Maintenance Rule (a)(4) risk calculation to reflect a postulated seasonal variation in LOOP frequency.

However, the base LOOP frequency is adjusted (i.e., increased) in the Maintenance Rule (a)(4) calculation to reflect severe weather in the vicinity of the plant. For example, plant procedures require that the base LOOP frequency be increased in the (a)(4) risk calculation when the National Weather Service issues a Severe Thunderstorm Warning or Tornado Warning for Callaway County. In addition, should a seasonal factor result in an actual grid condition that would require notification to the Callaway Plant from the transmission system operators at Ameren, the base LOOP frequency in the (a)(4) risk calculation would be appropriately adjusted.Based on the above discussion, AmerenUE believes that its approach to adjusting the base LOOP frequency in Maintenance Rule (a)(4) risk calculations for Callaway Plant is appropriate since it reflects actual, real-time environmental conditions that may impact LOOP frequency, in lieu of making an adjustment, by season, to the LOOP frequency.

4 of 6 Attachment to ULNRC-05362 Offsite Source Operability and Alarm Limits Callaway Plant Operating Modes 1 -4 Contingency Computer Offsite Source Configuration Analysis Points/Computer Ctgr (Regulating Equipment Calculated Digital Display Category 8 Line-up) Operability Operability Operabimity Limits Limit DUAL SOURCE LTCs AUTO & CAP Banks # 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN* & CAP Banks 372.6 -335.7 kV 372.6 -337.7 kV 372.6 -339.0 kV LTCs AUTO & No CAP Banks 372.6 -341.2 kV 372.6 -343.2 kV 372.6 -344.2 kV LTCs MAN* & No CAP Banks 372.6 -347.1 kV 372.6 -349.1 kV 372.6 -350.0 kV SINGLE SOURCE LTCs AUTO & CAP Banks # 372.6 -332.9 kV 372.6 -334.9 kV 372.6 -336.0 kV LTCs MAN* & CAP Banks 372.6 -344.3 kV 372.6 -346.3 kV 372.6 -347.0 kV LTCs AUTO & No CAP Banks 372.6 -344.3 kV 372.6 -346.3 kV 372.6 -347.3 kV LTCs MAN* & No CAP Banks Operation Not Operation Not Operation Not Allowed Allowed Allowed# These are the only voltages included in the Transmission Provider Agreement.

Other voltages are dependent upon grid conditions.

If in MAN, the LTC secondary shall be set (fixed) at the 13 tap.Page 5 of 6 Attachment to ULNRC-05362 Offsite Source Operabilitv and Alarm Limits (Cont.)Callaway Plant Operating Modes 5, 6 and No Mode Contingency Computer Offsite Source Configuration Analysis Points/Computer Ctgr (Regulating Equipment Calculated Digital Display Category 8 Line-up) Operability Operability OperailityLimits Limit DUAL SOURCE LTCs AUTO & CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & CAP Banks 372.6 -335.7 kV 372.6 -337.7 kV 372.6 -339.0 kV LTCs AUTO & No CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & No CAP Banks 372.6 -345.7 kV 372.6 -347.7 kV 372.6 -349.0 kV SINGLE SOURCE LTCs AUTO& CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & CAP Banks 372.6 -344.3 kV 372.6 -346.3 kV 372.6 -347.0 kV LTCs AUTO& No CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & No CAP Banks 372.6 -351.9 kV 372.6 -353.9 kV 372.6 -355.0 kV** If in MAN, the LTC secondary shall be set (fixed) at either the 12 tap or the 13 tap.Page 6 of 6

Text

AnmerenUE Callaway Plant PO Box 620 Fulton, MO 65251 January 31, 2007 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop P1-137 Washington, DC 20555-0001 Ladie A meremn UE s and Gentlemen:

ULNRC-05362 DOCKET NUMBER 50-483 CALLAWAY PLANT UNIT 1 UNION ELECTRIC CO.RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING GENERIC LETTER 2006-02,"GRID RELIABILITY AND THE IMPACT ON PLANT RISK AND THE OPERABILITY OF OFFSITE POWER"

References:

1.USNRC Generic Letter 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," dated February 1, 2006 2. AmerenUE letter ULNRC-05270, "60-Day Response to NRC Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power,"' dated March 31, 2006 3. AmerenUE letter ULNRC-05313, "Follow-up Response to NRC Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power,"' dated August 1, 2006 4. USNRC Letter, "Request for Additional Information Regarding Resolution of Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power' (TAC Nos. MD0947 through MD 1050)," dated December 5, 2006 On February 1, 2006, the NRC issued Generic Letter (GL) 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," (Reference 1). The GL sought to obtain information from licensees to determine if compliance is being maintained with NRC regulatory requirements governing electric power sources and associated personnel training.

AmerenUE (Union Electric) provided its response for Callaway Plant by letter dated March 31, 2006 (Reference 2), as modified by a follow-up letter dated August 1, 2006 (Reference 3).A23 a subsidiary of Ameren Corporation ULNRC-05362 January 31, 2007 Page 2 From its review of all the licensee responses to GL 2006-02, the NRC determined that additional information is needed to resolve some of the issues discussed in the GL.By letter dated December 5, 2006 (Reference

4) the NRC issued a request for additional information (RAI) to licensees.

The specific questions asked per the RAI were listed in Enclosure 2 of the letter. Since not all of the RAI questions pertain to each plant, Enclosure 3 of the letter provided a listing that identifies which questions apply to which facility.

For Callaway Plant, RAI questions 1, 4, and 5 were identified to be applicable.

In response to the NRC's RAI, AmerenUE hereby provides the additional information requested for Callaway Plant, i.e., responses to questions 1, 4, and 5 of the RAI. The responses are provided in the attachment to this letter.It may be noted that no regulatory commitments are made per this letter or its attachment.

For any questions regarding this letter or its attachment, please contact David Shafer at either 314-554-3104 or 573-676-4722.

I declare under penalty of perjury that the foregoing and attached are true and correct.Sincerely, Executed on January 31, 2007 David T. Fitzgerald Manager-Regulatory Affairs TBE/jdg Attachment ULNRC-05362 January 31, 2007 Page 3 cc: Mr. Bruce S. Mallett Regional Administrator U.S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-4005 Senior Resident Inspector Callaway Resident Office U.S. Nuclear Regulatory Commission 8201 NRC Road Steedman, MO 65077 Mr. Jack N. Donohew (2 copies)Licensing Project Manager, Callaway Plant Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop O-7D1 Washington, DC 20555-2738 Missouri Public Service Commission Governor Office Building 200 Madison Street PO Box 360 Jefferson City, MO 65102-0360 Mr. Ron Reynolds Director Missouri State Emergency Management Agency P.O. Box 116 Jefferson City, MO 65102 ULNRC-05362 January 31, 2007 Page 4 bcc: C. D. Naslund A. C. Heflin D. T. Fitzgerald L. E. Thibault T. E. Herrmann D. W. Neterer G. A. Hughes D. E. Shafer T. B. Elwood (470)S. L. Gallagher (100)L. M. Belsky (NSRB)D. R. Waller D. S. Turley M. L. Wedel (630)J. V. Hackman (630)A160.0761 Certrec Corporation 4200 South Hulen, Suite 630 Fort Worth, TX 76109 (Certrec receives ALL attachments as long as they are non-safeguards and publicly disclosed).

Send the following without attachments:

Ms. Diane M. Hooper Supervisor, Licensing WCNOC P.O. Box 411 Burlington, KS 66839 Mr. Scott Bauer Regulatory Affairs Palo Verde NGS P.O. Box 52034, Mail Station 7636 Phoenix, AZ 85072-2034 Mr. Scott Head Supervisor, Licensing South Texas Project NOC Mail Code N5014 P.O. Box 289 Wadsworth, TX 77483 Mr. Dennis Buschbaum TXU Power Comanche Peak SES P.O. Box 1002 Glen Rose, TX 76043 Mr. Stan Ketelsen Manager, Regulatory Services Pacific Gas & Electric Mail Stop 104/5/536 P.O. Box 56 Avila Beach, CA 93424 Mr. John O'Neill Pillsbury Winthrop Shaw Pittman LLP 2300 N. Street N.W.Washington, DC 20037 Attachment to ULNRC-05362 AmerenUE Response to Request for Additional Information (RAI)Regarding Information and Responses Provided for Callaway Plant in Response to Generic Letter 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power" By letter dated December 5, 2006 the NRC issued a request for additional information (RAI) to licensees regarding the information and answers provided by licensees in response to the topics and questions contained in GL 2006-02. The specific RAI requests/questions were listed in Enclosure 2 of the letter. Since not all of the RAI questions pertain to each plant, Enclosure 3 of the letter provided a listing identifying which questions apply to which facility.

For Callaway Plant, RAI questions 1, 4, and 5 were identified to be applicable.

In response to the RAI, AmerenUE provides the following responses to Questions 1, 4, and 5 for Callaway Plant. For each case, the RAI question is given, followed by AmerenUE's response.1. Switchyard Minimum Voltage: In response to question 1(g) [of the GL] you did not identify specific minimum switchyard voltage limits (kV) that you supplied to the local transmission entity. Please, provide the following information:

What is the specific minimum acceptable switchyard voltage included in your protocol agreement with your grid operator (GO) and what was the basis for this value? How is this value related to your Technical Specification degraded voltage relay setpoints?

AmerenUE Response: The specified minimum off-site switchyard voltage (post unit trip) is related to the voltage required to reset the Technical Specification degraded voltage relays plus an uncertainty which includes sensor accuracy and bistable setting tolerance.

The Technical Specification degraded voltage relays for Callaway Plant monitor the safety-related 4160-VAC buses and have a reset value of 3808 Volts. The relays have an associated time delay of 8 seconds with a safety injection (SI) signal present or 119 seconds without an ST signal present. This degraded voltage reset value corresponds to a switchyard voltage of 329.8 kV when computed using load flow analysis with safety injection loads present (

Reference:

Callaway calculation NB-05 and ZZ-62). Refer to the tables provided on pages 5 and 6 of this attachment for voltage operability values based on plant operating Mode and voltage regulating equipment line-up. The tables are taken from Callaway Plant Operations Surveillance Procedure OSP-NB-00001, "Class lE Electrical Source Verification." 1 of 6 Attachment to ULNRC-05362 As addressed by Callaway procedure OSP-NB-00001, when the main generator is on line, the actual switchyard voltage indicated on the main control board and the plant computer is not indicative of what switchyard voltage would be following a reactor trip. This is due to the voltage support provided by the main generator.

Therefore, when the generator is on line, a predicted contingency voltage that is determined from the Real Time Contingency Analysis (RTCA) program, along with the"Category 8 Alarm" that may be present, is used to determine OPERABILITY of the offsite AC sources. The Category 8 Callaway Switchyard Alarm is an Ameren Transmission Operator alarm actuated by the RTCA and is set approximately 3 kV above the OPERABILITY limit. Ameren Transmission Operations will respond to this alarm and take necessary actions to restore acceptable voltage in the transmission system.4. Identification of Applicable Single Contingencies:

In response to question 3(a) [of the GL] you did not identify the loss of other critical transmission elements that may cause the offsite power system (OSP) to degrade, other than the loss of the nuclear unit. If it is possible for specific critical transmission elements (such as other generators, critical transmission line, transformers, capacitor banks, voltage regulators, etc.) to degrade the OSP such that inadequate post-trip voltage could result, have these elements been included in your N-1 contingency analysis?

When these elements are included in your GO's contingency analysis model and failure of one of these transmission elements could result in actuation of your degraded voltage grid relay, is the offsite power declared inoperable?

If not, what is your basis for not declaring the offsite power inoperable?

AmerenUE Response: Both the Midwest Independent System Operator (MISO) and Ameren Transmission real time contingency analysis (RTCA) programs include N-1 contingencies for all major transmission lines, generation units and bulk transformers (e.g., 345 kV/13.8 kV) in their systems. At present, there are 460 N-1 contingencies factored into the Ameren Transmission RTCA program, which are run by the computer program on a six-minute interval.

The list is continually reviewed, and contingencies are added or modified as needed (such as when changes are made to the transmission system). These contingencies are run against the existing grid conditions and thereby used to predict the Cailaway switchyard post-trip voltage in the case of each contingency.

Although it is highly unlikely that a postulated loss of a facility other than the nuclear unit would degrade switchyard voltage to below the minimum required value with the Callaway main generator on-line, in the event the predicted voltage is below the "Category 8 Alarm" setpoint, Callaway Operations would be alerted to evaluate OPERABILITY of the off-site sources based on the requirements specified in 2 of 6 Attachment to ULNRC-05362 Callaway procedure OSP-NB-00001. (This procedure provides the minimum switchyard voltage that relates directly to the degraded voltage relay setpoints.)

In such cases, offsite source OPERABILITY may be conservatively assessed based on all contingencies factored into the RTCA; however, the offsite sources would not necessarily be declared inoperable for the postulated loss of a facility (other than the nuclear unit) without additional evaluations of overall grid conditions.

When the nuclear unit (Callaway Plant) is already off-line, Technical Specifications are not entered at Callaway Plant for grid conditions that might occur. Operability of the Callaway offsite power sources is monitored via the Category 8 Alarm and the predicted voltage value provided by the Ameren Transmission Operator.

If Callaway Plant is notified by the Ameren Transmission Operator that a Category 8 alarm is present, then operators will respond in accordance with OSP-NB-00001 and make a determination regarding offsite source operability based on the actual metered voltage. In this condition, postulated contingencies on the transmission grid are not used as a basis for operability determinations since:* Such events are only postulated and have not actually occurred.* The offsite power circuits remain capable of effecting a safe plant shutdown and mitigating the effects of an accident, and* The GDC-17 criterion discussed in the Generic Letter is still met, i.e., loss of power from the transmission network would not occur as a result of loss of power generated by Callaway Plant.It should be noted that compliance with GDC-17 was taken into account in the design and licensing of Callaway Plant. The requirements of the Technical Specifications with regard to the "qualified circuits between the offsite transmission network and the onsite Class IE AC electrical power distribution system" and the associated operability requirements specified therein are viewed to have a separate or different intent and scope relative to GDC-17. Nevertheless, procedures have been established based on application of the agreement with MISO and Ameren Transmission (as described in AmerenUE's March 31, 2006 response to GL 2006-02), and those procedures are used during plant operation to evaluate switchyard voltage levels for appropriate contingencies, including a Callaway Plant trip, and to thus conservatively assess operability of the offsite power system for determining whether entry into a Condition(s) and Required Action(s) of Callaway Technical Specification 3.8.1, "AC Sources-Operating," should be made.5. Seasonal Variation in Grid Stress (Reliability and Loss-of-offsite Power (LOOP)Probability):

Certain regions during certain times of the year (seasonal variations) experience higher grid stress as is indicated in Electric Power Research Institute (EPRI) Report 1011759, Table 4-7, Grid LOOP Adjustment Factor, and NRC NUREG/CR-6890.

Do you adjust the base LOOP frequency in your probabilistic risk assessment (PRA) and Maintenance Rule evaluations for various seasons? If 3 of 6 Attachment to ULNRC-05362 you do not consider seasonal variations in base LOOP frequency in your PRA and Maintenance Rule evaluations, explain why it is acceptable to do so.AmerenUE Response: As stated in AmerenUE's March 31, 2006 response to Question 5(c) of GL 2006-02, there are no apparent seasonal variations that affect LOOP frequency.

Consequently, Callaway does not adjust the base LOOP frequency in the Maintenance Rule (a)(4) risk calculation to reflect a postulated seasonal variation in LOOP frequency.

However, the base LOOP frequency is adjusted (i.e., increased) in the Maintenance Rule (a)(4) calculation to reflect severe weather in the vicinity of the plant. For example, plant procedures require that the base LOOP frequency be increased in the (a)(4) risk calculation when the National Weather Service issues a Severe Thunderstorm Warning or Tornado Warning for Callaway County. In addition, should a seasonal factor result in an actual grid condition that would require notification to the Callaway Plant from the transmission system operators at Ameren, the base LOOP frequency in the (a)(4) risk calculation would be appropriately adjusted.Based on the above discussion, AmerenUE believes that its approach to adjusting the base LOOP frequency in Maintenance Rule (a)(4) risk calculations for Callaway Plant is appropriate since it reflects actual, real-time environmental conditions that may impact LOOP frequency, in lieu of making an adjustment, by season, to the LOOP frequency.

4 of 6 Attachment to ULNRC-05362 Offsite Source Operability and Alarm Limits Callaway Plant Operating Modes 1 -4 Contingency Computer Offsite Source Configuration Analysis Points/Computer Ctgr (Regulating Equipment Calculated Digital Display Category 8 Line-up) Operability Operability Operabimity Limits Limit DUAL SOURCE LTCs AUTO & CAP Banks # 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN* & CAP Banks 372.6 -335.7 kV 372.6 -337.7 kV 372.6 -339.0 kV LTCs AUTO & No CAP Banks 372.6 -341.2 kV 372.6 -343.2 kV 372.6 -344.2 kV LTCs MAN* & No CAP Banks 372.6 -347.1 kV 372.6 -349.1 kV 372.6 -350.0 kV SINGLE SOURCE LTCs AUTO & CAP Banks # 372.6 -332.9 kV 372.6 -334.9 kV 372.6 -336.0 kV LTCs MAN* & CAP Banks 372.6 -344.3 kV 372.6 -346.3 kV 372.6 -347.0 kV LTCs AUTO & No CAP Banks 372.6 -344.3 kV 372.6 -346.3 kV 372.6 -347.3 kV LTCs MAN* & No CAP Banks Operation Not Operation Not Operation Not Allowed Allowed Allowed# These are the only voltages included in the Transmission Provider Agreement.

Other voltages are dependent upon grid conditions.

If in MAN, the LTC secondary shall be set (fixed) at the 13 tap.Page 5 of 6 Attachment to ULNRC-05362 Offsite Source Operabilitv and Alarm Limits (Cont.)Callaway Plant Operating Modes 5, 6 and No Mode Contingency Computer Offsite Source Configuration Analysis Points/Computer Ctgr (Regulating Equipment Calculated Digital Display Category 8 Line-up) Operability Operability OperailityLimits Limit DUAL SOURCE LTCs AUTO & CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & CAP Banks 372.6 -335.7 kV 372.6 -337.7 kV 372.6 -339.0 kV LTCs AUTO & No CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & No CAP Banks 372.6 -345.7 kV 372.6 -347.7 kV 372.6 -349.0 kV SINGLE SOURCE LTCs AUTO& CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & CAP Banks 372.6 -344.3 kV 372.6 -346.3 kV 372.6 -347.0 kV LTCs AUTO& No CAP Banks 372.6 -329.8 kV 372.6 -331.8 kV 372.6 -333.0 kV LTCs MAN** & No CAP Banks 372.6 -351.9 kV 372.6 -353.9 kV 372.6 -355.0 kV** If in MAN, the LTC secondary shall be set (fixed) at either the 12 tap or the 13 tap.Page 6 of 6

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